In the drilling of an underwater oil and gas well, it is common to install a series of coaxial casing assemblies extending into the ocean floor to different depths and suspended by a casing hanger mounted at the mudline within the wellhead or a hanger head disposed within the wellhead. An inner hanger apparatus will have a first device for automatically engaging a second device on the wellhead or an outer hanger head, as the case may be, during the time such inner hanger, suspending a string of tubing or casing, is being lowered into the well and so as to prevent further downward movement of such inner hanger and string.
In such installations, pressure control equipment is connected to the upper end of the wellhead, and the string is lowered into the well through such equipment for suspension from the wellhead. To lower the string, the hanger, connected to the upper end of the casing or tubing string, has means thereon for releasable connection to a running tool suspended from the lower end of a pipe string extending to the surface, and, as discussed above, a seat thereabout for landing on a seat in the bore of the wellhead as it is lowered by the tool, the coaxial casings forming an annulus.
Although reliance may be had on the weight of the casing or tubing to hold the hanger down within the well after it has landed, generally it is desirable to lock the hanger and string. Conventionally, means for locking the respective casing hangers in the wellhead housing are carried by the wellhead or outer hanger head and automatically interlock with an inner hanger when the inner hanger is landed within the wellhead.
Various prior art patents disclose means for locking a hanger down within the wellhead including U.S. Pat. Nos. 3,273,646; 3,404,736; 3,468,558; 3,468,559; 3,489,436; 3,492,026; 3,528,686; 3,664,689; 3,800,869; 3,827,488; and 3,918,747. However, most prior art devices do not provide for a positive holddown where the locking ring or latch is prevented from expanding or contracting so as to unlock the hanger within the well. Those which provide a type of positive holddown are in combination with a seal assembly where the positive holddown is not effected until the seal assembly is actuated. Such holddowns are then dependent upon the life of the seal ring in the assembly. See, for example, U.S. Pat. Nos. 3,404,736; 3,540,533; 3,664,689; 3,809,158 and 4,138,144.
Most prior art holddown latches include a sealing assembly which is subjected to the deleterious effects of the circulating cement and returns during the cementing operation. See, for example, U.S. Pat. Nos. 3,404,736; 3,528,686; 3,540,533; 3,664,689; 3,809,158; 3,827,488; and 3,918,747. This is true even where the holddown assemblies are independent of the seal assemblies. See U.S. Pat. Nos. 3,468,558; 3,468,559; 3,489,436; 3,492,026; and 3,827,488. Although U.S. Pat. No. 3,273,646 does not subject its sealing assembly to circulation, neither does it provide a positive holddown during the cementing operation.
The cementing operation includes anchoring the hanger and string in place by means of the cement which is conducted downwardly through the handling string and upwardly into the annulus between the suspended string and the well bore. There are flow passages through the hanger which connect the annulus with the bore of the wellhead above the seat so that returns may be taken up through the flow passages.
The cementing of a casing string within a wellhead structure is a difficult operation that is both costly and time consuming. Among the difficulties is the problem of insuring a solid cementing operation of the casing string within the incased portion of the hole and still providing a reliable means of effecting a secondary seal at the hanger. Many cementing systems operate on a volumetric basis wherein a predetermined amount or volume of cement is pumped into the well and allowed to flow up around the casing string to permanently secure it in place. However, leaks or cracks in the wellhead structure or ruptured strata of the hole itself may drain off a portion of the cement thereby preventing an adequate cementing of the casing. Should this crack or leak occur near the bottom of the hole, virtually all the cement may be drained off or lost from the annulus around the casing, thereby putting greater reliance on the secondary seal at the hanger to prevent any leakage of down hole pressure.
Proper completion of the well requires that the annulus formed by adjacent casings, be sealed off above the cement line after the cement has been forced into the annulus. Such a seal has been effected in the prior art by packoff assemblies that include a compressed seal element. See, for example, U.S. Pat. Nos. 3,273,646; 3,404,736; 3,468,558; 3,468,559; 3,489,436; 3,492,026; 3,528,686; 3,664,689; 3,800,869; 3,827,488; 3,918,747; 4,109,942; and 4,138,144. Such patents show a packoff assembly with a seal element disposed between an upper compression member and a lower compression member. In those disclosures, it can be seen that as a load is placed on the packoff assembly, downward movement of the lower compression member will eventually be precluded by stop means. By continuing the downward movement of the upper compression member, the seal element is compressed thereby expanding to seal against the hanger and head, thus sealing off the annulus.
Sealing off the cemented annulus around the casing is difficult in prior devices because the abrasive effect of liquids and solids displaced by cement sometimes rips or damages the seals, thereby preventing an effective seal. Furthermore, when seals are forced across threaded portions of the casing hanger, additional ripping, tearing or damage of the seals can occur.
U.S. Pat. No. 3,404,736 discloses an integral support ring/packoff assembly. This assembly includes an upper tubular member and a lower tubular member which are made up with one another by means of threads disposed about the upper end of the lower member and threads disposed about an intermediate portion of the upper member. The lower member has threads about its lower end for making up with intermediate threads on the hanger located above the annular seat supporting the hanger within the wellhead and below the running tool threads. The running tool threads are arranged radially inwardly on the hanger so that the lower tubular member is free to move downwardly over the running tool threads on the hanger and into position for engagement with the intermediate threads on the hanger.
The upper member is releasably attached to the running tool by means of pins projecting outwardly from the running tool for fitting within grooves about the upper end of the upper tubular member. These pins not only permit the entire assembly to be lowered onto the casing hanger, but also permit it to be rotated for anchoring thereto by the engagement of the intermediate hanger threads. The upper and lower tubular members are releasably connected against rotation related to one another by means of one or more shear pins so that a right-hand torque transmitted on the running tool by the drill string will be transmitted to the upper member and thus to the lower member for making up the intermediate threads on the hanger.
There is a frustoconical shoulder around the outer circumference of the lower tubular member positioned so as to be opposite an internal groove in the bore of the wellhead. There is a rigid split ring disposed above the shoulder on the lower member for radial expansion into the annular groove. An expander ring, which also functions as a lower compression ring for the seal assembly, has a cooperative tapered surface engaging a taper on the upper surface of the split ring where, upon the downward movement of the expander ring, the split ring is expanded radially outwardly into the annular groove to relieve the axial load of the hanger and string on the wellhead.
The seal assembly includes the expander ring as the lower compression member and a seal ring mounted around the lower tubular member and located above the expander ring. On top of te seal ring is an anti-friction ring whose upper surface engages the lower end of the upper tubular member.
To actuate the assembly, a right-hand torque is placed on the running tool causing the upper tubular member to move downwardly thereby expanding the split ring and energizing the seal ring. However, as has been pointed out, there is no positive holddown during the cementing operation and the suppot provided by the split ring is dependent upon the life of the seal ring. Further it should be noted that the purpose of the split ring is not to serve as a holddown but as an axial support to relieve part of the load on the hanger.
The prior art packoff assembly requires the dual sealing engagement of both the hanger and the wellhead. Should the packoff assembly fail to be centered within the annular recess formed by the hanger and the wellhead, the sealing assembly may engage only one of the sealing surfaces. This may result from the sealing element failing to sufficiently expand in one of the radial directions to contact a sealing surface.
The packoff assembly of the present invention is independent of the holddown and can be installed and the cemented annulus selectively sealed off, after the proper cementing job has been performed. The sealing means of the packoff assembly is never subjected to the abrasive effect of the fluid cement and is never forced across threads of other surfaces which may damage or have a deleterious effect on such sealing means. Such sealing means may then act as an effective, reliable, positive secondary seal supplementing the seal provided by the cemented annulus. The packoff assembly of the present invention operates in series whereby an inner sealing means sealingly engages the hanger independently of an outer sealing means engaging the wellhead.
Other objects and advantages of the invention will appear from the following description.